As described in my prior applications, many natural gas wells produce a relatively high pressure, high volume well stream effluent containing significant volumes of high vapor pressure condensates which will normally contain absorbed and dissolved natural gas, propane, butane, pentane and the like. Currently these liquid and dissolved hydrocarbons are only partially recovered by conventional, high pressure, separator units. The liquid hydrocarbon by products normally removed from the well stream by a high pressure separator unit, are collected and then typically dumped to a low pressure storage tank means for subsequent sale and use. A substantial amount of dissolved gas and high vapor pressure hydrocarbons remain in the liquid hydrocarbon by-products. Substantial amounts of these gases and hydrocarbons may vaporize by flashing in the storage tank due to the substantial reduction in pressure in the tank which permits the volatile components to evaporate or off-gas into gas and vapor collected in the storage tank over the condensate. In this manner, substantial amounts of gas and entrained liquid hydrocarbons are often vented to the atmosphere to reduce storage tank pressure and are wasted. In addition to this initial vaporization and loss, further evaporation occurs when the condensate stands for a period of time in the storage tank or when the condensate is subsequently transported to another location or during subsequent storage and/or processing. This is described in the industry as weathering. Many users of the condensate specify particular low vaporization pressure requirements for such condensate; and the salability and value of the condensate depends upon the characteristics of the condensate. Thus, natural gas wells, which produce significant amounts of high vapor pressure condensates along with the natural gas, present a great opportunity for improvement in production methods including a reduction in discharge to the environment and economic gain by recovery of otherwise wasted by-products.
While the apparatus and methods disclosed in my prior applications enable enhanced recovery of sales gas and hydrocarbon condensates in relatively high pressure, high volume wells, there is a need for improved production apparatus and methods for use with relatively low volume gas wells, (e.g., 1.5 million cubic feet per day or less). One of the problems with relatively low volume gas wells is that the pressure differential between shut-in and/or natural flow pressure of a small volume gas well and the pressure of the sales gas from other wells in the sales gas pipe line may be so low as to reduce and/or restrict the volume of production from the low volume wells because of inability to establish and maintain flow from the wellhead to the sales gas pipe line through the production equipment. Another problem with relatively low volume natural gas wells is that the natural flow pressure may vary substantially depending upon changes in formation conditions and the amount of liquid hydrocarbons and water in the well. Removal of liquid hydrocarbons and water is dependent upon the rate of flow of natural gas which may be so low in low volume wells as to prevent removal of sufficient quantities of the liquid hydrocarbons and water resulting in further reduction in rate of flow and sometimes, a well shut down condition which requires special procedures to unload the well to reestablish natural flow. Thus, it is desirable to establish and maintain sufficient pressure differentials between the sales gas pipe line pressure, the production equipment, and the natural flow pressure of the low volume well to assure satisfactory flow from the well into the production equipment and from the production equipment to the sales gas pipe line. For example, if the sales gas pipe line pressure is 500 psi and the shut-in or natural flow pressure of a low volume well is only 700 psi or lower, the pressure differential between the well head and the sales gas pipe line is only 200 psi or lower and may have an adverse effect on the flow rate from the well head. When the pressure differential is increased, for example, from 200 psi to 500 psi or more, the resistance to flow from the well head is reduced, and the volume and rate of gas flowing from the low volume well to the sales gas pipe line ma be substantially increased.
The construction of apparatus and utilization of methods of processing natural gas wellhead effluent at the well site requires consideration of a multitude of factors which are unique to variable conditions at the wellhead site. First, many wellhead sites are located in remote areas where there are no on-site operating personnel and which are not readily accessible by remotely located operating personnel. Second, many wellhead sites are located in geographical areas subject to extreme changes in climatic conditions from a winter period with ice, snow and extremely low temperature conditions (e.g., 32 degrees F. to -50 degrees F.) to a summer period with extremely high temperature conditions (e.g., 90 degrees F. to 120 degrees F.). Thus, while environmental conditions may be controlled at central processing and production plants, environmental conditions at a natural gas wellhead site are generally uncontrollable and processing and production equipment at the wellhead site are subject to extreme environmental conditions without constant availability of on-site maintenance and operating service personnel. Thus, an important consideration feature and object of the present invention is to provide reliable, substantially maintenance free and service free production apparatus and methods which are usable at a wellhead site. Some types of oil-gas production apparatus and methods which may be satisfactorily operated in a controlled environment at a central production facility cannot be reliably operated at a wellhead site. Thus, the design of on-site wellhead production equipment and processes requires consideration of many factors which are not applicable to central production facilities.
The terms, gaseous hydrocarbon hydrate temperature and the like, as used herein, are known terms of art which mean a relatively low temperature at which gaseous hydrocarbons form a porous solid. This solid is crystallized in a cubic structure in which gas molecules are "trapped" in cavities. Hydrates are capable of blocking flow of gaseous hydrocarbons in a processing system. The formation of such hydrates is a function of the kind of hydrocarbon, associated free water and pressure and temperature conditions thereof. Exemplary known hydrate temperatures are shown in various prior art publications. The systems of the present invention are designed to operate at temperatures above gaseous hydrocarbon hydrate temperatures.
In general, the low pressure and high pressure separator means of the present invention comprise a vessel (tank) of any size or shape mounted in either a vertical or horizontal attitude and designed and constructed and arranged to operate at suitable pressures and at elevated temperatures in excess of process gas hydrate temperatures. Fluids in such vessels are primarily mechanically separated into gaseous and liquid phases by change of direction of flow, decrease in velocity, scrubbing, etc. in a two-phase (gaseous/liquid separation) or three-phase (gaseous/liquid separation and then water-hydrocarbon liquid separation). Suitable level controls, motor valves, temperature controllers, etc. are utilized to maintain the desired continuous process conditions.